Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms an area or reservoir in which hydrocarbons will collect. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then can flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.
When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. Cement is introduced through a work string. As it flows out the bottom of the work string, fluids already in the well, so-called “returns,” are displaced up the annulus between the casing and the borehole and are collected at the surface.
Once the casing is cemented in place, it is perforated at the level of the oil-bearing formation to create openings through which oil can enter the cased well. Production tubing, valves, and other equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production tubing up to the surface for storage or transport.
This simplified drilling and completion process, however, is rarely possible in the real world. Hydrocarbon bearing formations may be quite deep or otherwise difficult to access. Thus, many wells today are drilled in stages. An initial section is drilled, cased, and cemented. Drilling then proceeds with a somewhat smaller well bore which is lined with somewhat smaller casings or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A seal also is typically established between the liner and the casing and, like the original casing, the liner is cemented in the well. That process then may be repeated to further extend the well and install additional liners. In essence, then, a modern oil well typically includes a number of tubes telescoped wholly or partially within other tubes.
Moreover, hydrocarbons are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons can flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.
One technique involves drilling a well in a more or less horizontal direction, so that the borehole extends along a formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Another technique involves creating fractures in a formation which will allow hydrocarbons to flow more easily. Indeed, the combination of horizontal drilling and fracturing, or “frac'ing” or “fracking” as it is known in the industry, is presently the only commercially viable way of producing natural gas from the vast majority of North American gas reserves.
Fracturing a formation is accomplished by pumping fluid, most commonly water, into the well at high pressure and flow rates. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the fluid along with gelling agents to create a slurry. The slurry is injected into the formation, fracturing it and creating flow paths to the well. The proppant serves to prevent fractures from closing when pumping is stopped.
A formation typically will be fractured in many different locations or zones, but rarely, if ever, will it be fractured all at once. A liner first will be installed in the well. The liner will incorporate valves, or the liner may be perforated in a first zone near the bottom of the well. Fluids then are pumped into the well to fracture the formation in the vicinity of the bottom perforations. After the initial zone is fractured, a plug is installed in the liner at a point above the fractured zone. The liner is perforated again, this time in a second zone located above the plug. That process is repeated for zones further up the formation until the formation has been completely fractured.
Once the well is fractured, the large quantities of water and sand that were injected into the formation eventually must be allowed to flow out of the well. The water and sand will be separated from hydrocarbons produced by the well to protect downstream equipment from damage and corrosion. The production stream also may require additional processing to neutralize corrosive agents in the stream.
Systems for successfully completing a fracturing operation, therefore, are extensive and complex, as may be appreciated from FIG. 1. Water from tanks 1 and gelling agents dispensed by a chemical unit 2 are mixed in a hydration unit 3. The discharge from hydration unit 3, along with sand carried on conveyors 4 from sand tanks 5 is fed into a blending unit 6. Blender 6 mixes the gelled water and sand into a slurry. The slurry is discharged through low-pressure hoses 7 which convey it into two or more low-pressure lines 8 in a frac manifold 9. The low-pressure lines 8 in frac manifold 9 feed the slurry to an array of pumps 10, perhaps as many as a dozen or more, through low-pressure “suction” hoses 11.
Pumps 10 take the slurry and discharge it at high pressure through individual high-pressure “discharge” lines 12 into two or more high-pressure lines or “missiles” 13 on frac manifold 9. Missiles 13 flow together, i.e., they are manifolded on frac manifold 9. Several high-pressure flow lines 14 run from the manifolded missiles 13 to a “goat head” 15. Goat head 15 delivers the slurry into a “zipper” manifold 16 (also referred to by some as a “frac manifold”). Zipper manifold 16 allows the slurry to be selectively diverted to, for example, one of two well heads 17. Once fracturing is complete, flow back from the fracturing operation discharges into a flowback manifold 18 which leads into flowback tanks 19.
Frac systems are viewed as having “low-pressure” and “high-pressure” sides or, more simply, as having low sides and high sides. The low side includes the components upstream of the inlet of pumps 10, e.g., water tanks 1, hydration unit 3, blending unit 6, and the low-pressure lines 8 of frac manifold 9, which operate under relatively low pressures. The high side includes all the components downstream of the discharge outlets of pumps 10, e.g., the high-pressure missiles 13 of frac manifold 9 and flow lines 14 running to goat head 15, which operate under relatively high pressures.
The larger units of a frac system are transported to a well site on skid, trailers, or trucks and then connected by one kind of conduit or another. The conduits on the low-pressure side typically will be flexible hoses, such as blender hoses 7 and suction hoses 11. On the other hand, flow lines 14 running to goat head 15 and other high-pressure side conduits will be subject to extremely high pressures. They must be more rugged. They also typically will be assembled on site.
Flow lines 14 and other portions of the high-side that are assembled on site are made up from a variety of components often referred to as “frac iron,” “flow iron,” or “ground iron.” Such components include sections of straight steel pipe, such as pup joints. Also included are various fittings which provide junctions at which flow through conduits is split or combined, such as tees, crosses, laterals, and wyes. In addition to junction fittings, flow line components include fittings which are used to alter the course of a flow line. Such directional fittings include elbows and swivel joints. High-pressure flow lines also incorporate gauges and other monitoring equipment, as well as control devices such as shut off, plug, check, throttle, pressure release, butterfly, and choke valves.
Because frac systems are required at a site for a relatively short period of time, frac iron components are joined by unions. Unions allow the components to be connected (“made up”) and disconnected (“broken down”) relatively quickly. The three types of unions commonly used in frac systems are hammer (or “Weco®”) unions, clamp (or “Greyloc®”) unions, and flange unions. Though spoken of in terms that may imply they are discreet components, unions are actually interconnected subassemblies of the components joined by the union. A male sub will be on one component, and a mating female sub will be on the other. The subs then will be connected to each other to provide the union.
Flange unions, at least in comparison to threaded connections, may be made up and broken down with relative ease. Their basic design is robust and reliable, and like other flowline components, they are fabricated from heavy, high tensile steel. Thus, they have been adapted for low pressure (1,000 to 2,000 psi), medium pressure (2,000 to 4,000 psi), and high pressure service (6,000 to 20,000 psi). Moreover, unlike hammer and clamp unions, flange unions do not rely on seals that are exposed to fluids passing through the union.
Flange unions, as their name implies, typically provide a connection between two flanged components, such as spooled pipe or simply “spools.” Spooled pipe is provided with annular flanges extending radially outward from each end, thus giving the pipe the appearance of a spool. The flanges provide flat surfaces or faces which allow two spools to mate at their flanges. The flanges also are provided with a number of bolt holes. The holes are arranged angularly around the flange. Thus, spooled pipes may be connected by bolting mating flanges together. Each flange will have an annular groove running concentrically around the pipe opening. An annular metal seal is carried in the grooves to provide a seal between the flanges.
Though not entirely apparent from the schematic representation of FIG. 1, it will be appreciated that conventional frac systems are assembled from a very large number of individual components. Assembly of so many units on site can be time consuming, expensive, and hazardous. Thus, some components of a frac system are assembled off site on skids or trailers and transported as a unit to the well site.
Commonly skidded units include not only process units, such as blender 6 and pumps 10, but also flow units. Frac manifold 9, for example, is an assembly of pipes, junctions, valves, and other flow line components that typically are assembled off-site. Collectively, they provide a flow unit that manifolds, distributes, and controls discharge from pumps 10. Zipper manifold 16 is another flow unit that at times is assembled off-site from separate flow line components. Zipper manifold 16 receives flow from flow lines 14 and selectively distributes it to multiple well heads 17.
Such units may have been assembled on site in the past. By skidding them, assembly time at the well site is greatly reduced. Moreover, the components typically may be assembled more efficiently and reliably, and may be tested more easily in an off-site facility. At the same time, however, a well head is fixed. Skidded units can be quite large, heavy, and moveable only with difficulty and limited precision. Flow lines, therefore, necessarily incorporate directional fittings, such as elbows and swivel joints, which allow its course to be altered to accommodate two unaligned units.
Elbow joints are simply curved sections of pipe which provide, for example, a 90° turn in a line. Swivel joints are elbow connections having one or more joints in the conduit. The joints are packed with beatings which allow portions of the conduit to rotate relative to each other, thus allowing swivel joints to accommodate varying alignments between the components which they connect. Accordingly, swivel joints can provide considerable flexibility in assembling a flow line between essentially immovable points.
Though much less common, swivel flanges also are used to provide similar flexibility. Swivel flanges have a flange mounted on a hub. The hub is formed, for example, at one end of a length of pipe. Bearings are packed around the hub, and the flange can rotate around the hub on the bearings. When joined together, a pair of swivel-flanged pipes and a pair of elbow joints, like swivel joints, can accommodate varying alignments between components to be joined. Consequently, it is rare, if ever, that the high-side of a frac system does not incorporate at least one or, more likely, multiple swivel joints or flanges.
The large number of individual components in a frac system is compounded by the fact that most conventional frac systems incorporate a large number of relatively small flow lines, typically 3″ and 4″ flow lines. In part that is unavoidable. The pumps cannot be deployed in series and the flow lines carrying their individual discharges must be manifolded. Likewise, if multiple wells are to be serviced by the same array of pumps without assembling and disassembling flow lines, at some point their collective discharge must be split or directed into different flowline segments.
On the other hand, multiple flow lines in many instances represent a design choice. That is, certain flow rates and pressures will be required to fracture a particular well. Those flow rates and pressures will determine the number and capacities of the pumps. The high-pressure side then is designed to deliver the required flow rate without exceeding a maximum or “erosional” flow velocity, typically about 40′/sec, through the system. Additional flow lines often are added to provide higher flow rates into a well. The net result is that a fracking system often is so complicated that it resembles to the uninitiated a tangled mass of spaghetti.
Efforts have been made to simplify the flow line by incorporating fewer segments. For example, the conventional frac system illustrated in FIG. 1 includes four flow lines 14 running from the high-pressure lines 13 of frac manifold 9 to goat head 15. Some frac systems now employ a single, larger flowline segment running in place of four smaller lines. A single larger flow line will incorporate fewer parts and, therefore, fewer potential leak points. Both in terms of direct material and labor costs, a single larger flow line often will be less expensive than multiple smaller lines.
Frac jobs, however, have become more extensive, both in terms of the pressures required to fracture a formation and the time required to complete all stages of an operation. Prior to horizontal drilling, a typical vertical well might require fracturing in only one, two or three zones at pressures usually well below 10,000 psi. Fracturing a horizontal well, however, may require fracturing in 20 or more zones. Horizontal wells in shale formations such as the Eagle Ford shale in South Texas typically require fracturing pressures of at least 9,000 psi and 6 to 8 hours or more of pumping. Horizontal wells in the Haynesville in northeast Texas and northwest Louisiana require pressures around 13,500 psi. Pumping may continue near continuously—at flow rates of 2 to 3 thousand gallons per minute (gpm) for several days before fracturing is complete.
Moreover, at least in the early stages of production, the flow back after fracturing also will be at high pressure and flow rates. The initial production stream from a fractured well flows at pressures in the range of from 3,000 to 5,000 psi, and more and more commonly up to 10,000 psi. The flow rates can approach a million cubic feet per hour or more.
Given the high number of components, leaking at unions is always a concern in frac systems. The unions may not always be assembled properly. Even when assembled to specification, however, such issues are exacerbated by the extremely high pressures and flow rates through the system. Many unions also incorporate elastomeric seals which are exposed to flow through the conduit and are particularly susceptible to leaking.
Moreover, the abrasive and corrosive nature of the slurry flowing through a frac system not only will accelerate deterioration of exposed elastomeric seals, it can rapidly erode and weaken conduit walls. Flow through relatively long straight sections of pipe is relatively laminar. Flow through other areas, however, such as unions where exposed seals often are present, may be quite turbulent. Erosion also is a more significant issue where a flow line changes directions. Flow will more directly impact conduit walls, causing more abrasion than that caused simply by fluid passing over the walls.
High pressures and flow rates also create vibrations through a flow line. Those vibrations create stress throughout the flow line, but especially at the unions. The resulting strain may create fracturing which may propagate and lead to catastrophic failure. In any event, fracturing renders the conduit more susceptible to erosion, corrosion, and fatigue.
Such issues may be addressed in part by conventional approaches such as skidding units and providing equivalent flow rates with fewer, larger conduits. The components in skidded units, in general, may be assembled closer to specifications more precisely. Moreover, skidded components typically are welded or otherwise anchored to the skid, and that can reduce vibrational stress on the components. Single lines also reduce the overall number of components, and therefore, the number of potential leak paths. Many components, however, are not skidded, and even relatively larger lines still experience such problems. In particular, even relatively large flow lines still invariably incorporate swivel joints or flanges and may have other relatively sharp changes in direction.
Flowline components also are quite expensive. Swivel joints and swivel flanges in particular are expensive and often comprise the single largest part expense of a high-side flow line. At the same time, the general issues discussed above seem to be more focused in respect to swivel joints and swivel flanges. Swivel joints often incorporate exposed elastomeric seals. Flow through swivel joints is relatively turbulent. Because they incorporate rotatable joints and connect unaligned components, swivel joints and swivel flanges are particularly susceptible to bending stress caused by vibration in the flow line. They also may be disassembled on site for service and may not always be reassembled to specification.
Any failure of flowline components on site may interrupt fracturing, potentially reducing its effectiveness and inevitably increasing the amount of time required to complete the operation. Catastrophic failure may endanger service personnel. Thus, flowline components must be certified and periodically recertified as complying with rated specifications. The harsh operating conditions to which they are exposed, however, may cause damage or weakening of the components which is difficult to detect, such as fatigue stress and microscopic fracturing. Thus, flow iron typically must be inspected off-site.
It also will be appreciated that, especially on the high-pressure side of the system, if a connection fails, large quantities of fluid can be ejected at very high pressures, causing the components to move violently and potentially injure workers. Thus, various restraint systems are employed to restrict movement of components in the event a connection fails. The most common form of restraint system uses strips or belts of fabric, usually incorporating Kevlar or other high strength fibers. The fabric belts are wound around both sides of the connection. If the connection fails, the wound fabric will restrict movement of the formerly connected components.
Finally, the cost of repeatedly recertifying or replacing components can add significantly to operating costs of the system. Thus, high-pressure flowline components are required to endure extremely abrasive fluids flowing at extremely high pressures and rates and, hopefully, to do so over an extended service life.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved high-pressure flowline unions and methods for connecting flowline components. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.